When a hydrocarbon-bearing, subterranean reservoir formation does not have enough permeability or flow capacity for the hydrocarbons to flow to the surface in economic quantities or at optimum rates, hydraulic fracturing or chemical (usually acid) stimulation is often used to increase the flow capacity. A wellbore penetrating a subterranean formation typically includes a metal pipe (casing) cemented into the original drill hole. Holes (perforations) are placed to penetrate through the casing and the cement sheath surrounding the casing to allow hydrocarbon flow into the wellbore and, if necessary, to allow treatment fluids to flow from the wellbore into the formation.
Hydraulic fracturing comprises injecting fluids (usually viscous shear thinning, non-Newtonian gels or emulsions) into a formation at such high pressures and rates that the reservoir rock fails and forms a planar, typically vertical, fracture (or fracture network) much like the fracture that extends through a wooden log as a wedge is driven into it. Granular proppant materials, such as sand, ceramic beads, or other materials, are generally injected with the later portion of the fracturing fluid to hold the fracture(s) open after the fluid pressure is released. Increased flow capacity from the reservoir results from the flow path left between grains of the proppant material within the fracture(s). In chemical stimulation treatments, flow capacity is improved by dissolving materials in the formation or otherwise changing formation properties.
Application of hydraulic fracturing as described above is a routine part of petroleum industry operations as applied to individual target zones of up to about 60 meters (200 feet) of gross, vertical thickness of subterranean formation. When there are multiple or layered reservoirs to be hydraulically fractured, or a very thick hydrocarbon-bearing formation (over about 60 meters), then alternate treatment techniques are required to obtain treatment of the entire target zone.
When multiple hydrocarbon-bearing zones are stimulated by hydraulic fracturing or chemical stimulation treatments, economic and technical gains are realized by injecting multiple treatment stages that can be diverted (or separated) by various means, including mechanical devices such as bridge plugs, packers, downhole valves, sliding sleeves, and baffle/plug combinations; ball sealers; particulates such as sand, ceramic material, proppant, salt, waxes, resins, or other compounds; or by alternative fluid systems such as viscosified fluids, gelled fluids, foams, or other chemically formulated fluids; or using limited entry methods.
In mechanical bridge plug diversion, for example, the deepest interval is first perforated and fracture stimulated, then the interval is typically isolated by a wireline-set bridge plug, and the process is repeated in the next interval up. Assuming ten target perforation intervals, treating 300 meters (1,000 feet) of formation in this manner would typically require ten jobs over a time interval of ten days to two weeks with not only multiple fracture treatments, but also multiple perforating and bridge plug running operations. At the end of the treatment process, a wellbore clean-out operation would be required to remove the bridge plugs and put the well on production. The major advantage of using bridge plugs or other mechanical diversion agents is high confidence that the entire target zone is treated. The major disadvantages are the high cost of treatment resulting from multiple trips into and out of the wellbore and the risk of complications resulting from so many operations in the well. For example, a bridge plug can become stuck in the casing and need to be drilled out at great expense. A further disadvantage is that the required wellbore clean-out operation may damage some of the successfully fractured intervals.
To overcome some of the limitations associated with completion operations that require multiple trips of hardware into and out of the wellbore to perforate and stimulate subterranean formations, methods and apparatus have been proposed for “single-trip” deployment of a downhole tool string to allow for fracture and chemical stimulation of zones in conjunction with perforating. Specifically, these methods and apparatus allow operations that minimize the number of required wellbore operations and time required to complete these operations, thereby reducing the stimulation treatment cost. The tool strings used for these types of applications can be very long and the tool assembly is subject to the erosive effect of proppant slurries when retained in the hole for multiple treatments. Stabilization and protection from damage of the tool assemblies becomes very important.
Further, excess friction pressure is generated when pumping stimulation fluids, particularly proppant-laden and/or high viscosity fluids, at high rates through long lengths of coiled tubing. Depending on the length and diameter of the coiled tubing, the fluid viscosity, and the maximum allowable surface hardware working pressures, pump rates could be limited to just a few barrels per minute; which, depending on the characteristics of a specific subterranean formation, may not allow effective placement of proppant during hydraulic fracture treatments or effective dissolution of formation materials during acid stimulation treatments.
In hydraulic fracturing operations, a sealing mechanism, such as a packer, can be used to provide isolation between the fracturing fluid and the lower portion of a cased wellbore. When the packer is activated or set within the casing below a region of perforations in a subterranean formation interval to be treated, the hydraulic fracturing fluid is directed into the perforations at high pressures to fracture the formation. When the high pressure fluid is applied above the set packer, there is a large axial downward force along the tool. Experiments have demonstrated that the frictional force between the packer and the casing wall is insufficient to balance the downward force. Therefore, a device, such as a slip assembly, is generally needed to react against the axial load from the fracturing fluid and prevent movement of the tool assembly downhole.
Slip assemblies are commonly used to stabilize a string of tools (i.e., a downhole tool assembly) during treatment operations by gripping the casing in resistance to axial forces in the set position. Slip assemblies can be actuated either hydraulically or mechanically. One example of a mechanically-actuated slip assembly known in the art uses a J-latch mechanism to set and unset the slip assembly by axial movement of an inner mandrel that moves independently of an outer sleeve held by the resistance of reaction springs in contact with the casing. However, current axial-loaded slip technology is limited in many areas. Materials and component designs used in existing tools are not optimized for large axial loads (e.g., about 445 kN (100,000 lbf)), and current tools, if used at such loads, can require large release loads and can exhibit poor performance. A “release load” as used herein is the applied axial force required to unset the slips and allow the assembly to again move freely along the length of the wellbore. In addition, the use of existing tools for multiple sets in several wells can lead to increased wear of the tool parts responsible for anchoring the assembly, which results in poor performance or tool failure. Existing slip assembly designs occupy a large portion of the casing cross-sectional area. For example, the existing slip assembly designed to be used in 14 cm (5.50 inch) outer diameter well casing (having an inside diameter as small as 11.9 cm (4.67 inches)) typically has an outer diameter of 11.4 cm (4.50 inches). This small free-flow area between the slip assembly and the casing results in large differential pressures when the slip assembly is exposed to large flow rates in the wellbore. Another weakness of existing designs is the inability to function in the presence of suspended solids in the wellbore fluid. With current designs, the solids can enter the mechanism that cycles the tool, such as a J-latch, and prevent its operation. In addition, existing reaction spring designs can become less effective when exposed to suspended solids.
Accordingly, there is a need for improved apparatus and methods for stabilizing downhole tool assemblies in the wellbore during completion operations.